Permian Resources Corp Q2 FY2025 Earnings Call

Good morning, and welcome to Permian Resources conference call to discuss its second quarter 2025 earnings. Today's call is being recorded. A replay of the call will be accessible until August 21, 2025 by dialing 888-660-6264 and entering the replay access code 92721 or by visiting the company's website at www.permianres.com. At this time, I will turn the call over to Hays Mabry, Permian Resources Vice President of Investor Relations, for some opening remarks. Please go ahead, sir.

Thanks, John, and thank you all for joining us. On the call today are Will Hickey and James Walter, our Chief Executive Officers; and Guy Oliphint, our Chief Financial Officer. I would like to note that many of the comments during this call are forward-looking statements that involve risks and uncertainties that could affect our actual results or plans. Many of these risks are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our filings with the SEC. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results may differ materially. We may also refer to non-GAAP financial measures. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation. With that, I will turn the call over to Will Hickey, Co-CEO.

Thanks, Hays. We are excited to discuss our second quarter results this morning. The operations team delivered our 11th consecutive quarter of solid operational execution in Q2 that included the fastest well drilled, some of the most drilled feet per day and the lowest completion cost per foot in the company's history. This execution, combined with continued strong well results support us raising our full year production guidance while delivering a lower CapEx guidance than originally announced in February. Q2 was also a very volatile quarter that presented an opportunity for us to demonstrate our downturn playbook. In April, we opportunistically executed our buyback program with repurchases of $43 million of shares at an average price of $10.52 per share. In May, we signed the approximately $600 million Apache acquisition at lower than mid-cycle commodity prices. This acquisition is the exact type of deal we like to do with meaningful overlap with our existing assets, strong free cash flow, and inventory that competes for capital immediately. We closed the acquisition approximately 6 weeks ago and are even more excited about our ability to optimize operations and the acreage position. These types of countercyclical investments are exactly what we want to do to be able to deliver leading shareholder returns throughout the cycles. And we've done this while maintaining leverage of approximately 1x and liquidity of approximately $3 billion. After executing on all aspects of our downturn playbook and taking advantage of recent market volatility, we are still in a prime position to pursue further investment opportunities to create long-term shareholder value. Moving to Q2 reporting details. Production exceeded expectations with oil production of 176.5 barrels of oil per day, which includes approximately 900 barrels of oil per day from the Apache acquisition, which is in line with our prior messaging. Total production for the quarter was 385,000 barrels of oil equivalent per day. Results were driven by strong well performance from both our base wells and recent POPs, which resulted in adjusted operating cash flow of $817 million and adjusted free cash flow of $312 million with $505 million of cash CapEx. Additionally, our ground game machine continues to fire on all cylinders as we added 1,300 net acres across 130 different grassroots acquisitions in Q2 to build additional interest ahead of near-term development. These opportunities remain some of the highest returning investments in our portfolio and are a core piece of the PR story to maximize the value of our assets. With that, I'll turn it over to James.

Thanks, Will. Turning to Slide 5. Our strong balance sheet is what gives us the confidence to prudently invest capital across all cycles in our business. This has been a key part of our business model for the last 10 years and remains a core part of our strategy going forward. One of our primary goals has always been to achieve investment-grade status, and we are thrilled to announce that we have received our first investment-grade rating from Fitch. We are proud that Fitch recognized our strong credit metrics and track record of operating with a financial strategy consistent with an investment-grade company and we would expect the other rating agencies to reflect investment-grade status in the near term. We are fortunate that the PR business generates tremendous free cash flow, which allowed us to execute a $600 million bolt-on and $45 million share buybacks with cash on hand, all aligned in Q2 with leverage at 1x and $3 billion of liquidity. We generate significant free cash flow going forward. The beauty of the PR business today is we don't have to choose between debt repayment, acquisitions, buybacks, or building cash. We can execute on all of these as soon as opportunities present themselves. This provides the ultimate flexibility to efficiently allocate capital and drive value for shareholders. Turning to Slide 6. We want to spend some time discussing our Permian Resources as approaching the marketing of our hydrocarbons. Given our rapid growth, we have historically focused our midstream and marketing efforts on flow assurance and low fees. We have been extremely effective in ensuring all of our hydrocarbons get to market with zero interruptions over the past 10 years. But as our business has grown to the scale it is today, it has become apparent that our marketing strategy needs to evolve. Over the past 12 months, we've built out the full midstream marketing team in Midland that has made great progress selling more hydrocarbons downstream in the Permian Basin and improving our netbacks. We are fortunate to have had significant flexibility to change the sales point for a large percentage of our crude and gas volumes, and we are pleased to announce we've recently entered into multiple new transportation and marketing agreements to optimize PR's pricing. Slide 7 gets into a little more detail on the impact of the recent downstream contracts we have executed. On the gas side, we have entered into multiple transportation and marketing agreements to sell a significant portion of residue natural gas to non-Waha hubs along the Gulf Coast, Central Texas, and East Texas. These agreements should provide an incremental 75 million cubic feet a day of firm transport by year-end 2025, which ramps to 450 million a day by year-end 2028. On the crude side, we have entered into multiple new crude oil purchase agreements, providing improved netbacks, diversified pricing, and increasing exposure to the Gulf Coast markets. We expect the net impact of these agreements to improve our gas netbacks by over $0.10 per Mcf and our crude netbacks by over $0.50 per barrel. The cumulative effect of all this effort by our team resulted in a $50 million uplift to 2026 free cash flow versus 2024. We're excited about what we've done in the past 12 months on the marketing side and still retain significant flexibility for further optimization. Turning to Slide 8. We are excited to roll out a revised plan that incorporates our recent bolt-on that closed in June. This plan reflects an increase to the original full year 2025 production guidance by 3% while lowering the capital budget by 2%. The only other major update to point out is the impact of the One Big Beautiful Bill Act. Overall, we view the recent bill as a strong step towards further unlocking the potential of U.S. shale. The tax provision should further incentivize investment in domestic shale production and meaningfully reduce Permian Resources taxes over the coming years. We expect current cash taxes to be less than $5 million in 2025 and less than $50 million cumulatively in 2026 and 2027. In addition, our industry will benefit from the reduction in red tape associated with federal drilling permits and federal lease sales, the reduction in complexity of commingling federal and state production, and the further incentives for research and development. It is our belief that these tax and regulatory benefits far outweigh the modest impact we expect tariffs to have on steel and other input costs. I'll be concluding today's prepared remarks on Slide 9, where we reemphasize our value proposition for investors. We are proud of the hard work our team has put in and the strong returns that work has delivered for investors so far. I think it's important to point out that this peer-leading total shareholder return has been driven by the growth in free cash flow per share rather than a re-rating of our multiple. We believe our balance sheet, our industry-leading cost structure, and low breakevens position us to succeed and create value for investors in any commodity price environment. Thank you for tuning in today. And now I'll turn it back to the operator for Q&A.

Ladies and gentlemen, we will now begin the question-and-answer session. We now have our first question, and this comes from Scott Hanold from RBC Capital Markets.

I wouldn't mind a little bit of color on your recent production performance. It looks like you've filled less than half your planned program for 2025 and Q2's outperformance. I guess, relative to my model, was pretty strong. I think there might have been some improved NGL yields in there. But can you just generally really talk about like, maybe was the timing of sales or the type of well you're drawing because performance did feel pretty robust this quarter.

Yes, the first half of the year has been productive. We drilled some excellent wells, and our production comes from multiple sources. The majority of our barrels each quarter come from base production. We've had a fortunate summer with mild weather, leading to impressive downtime statistics. The results from our wells continue to be impressive; the Delaware Basin has really been the area to focus on, and high-quality rock consistently delivers strong performance. We've been consistently meeting or exceeding our targets quarter after quarter, which reflects the quality of our rock.

Okay. And as my follow-up, when you sort of look at the landscape right now, it obviously feels a lot better than it did back in the first quarter. But as you look going forward in this relative outperformance, I guess this year, you did step up your production guidance, obviously, related to the outperformance, but on a relative basis, unchanged CapEx. How do you think about maybe letting some of that benefit accrue to production versus the capital side? Is it in part due to the commodity price outlook? Or is it more just what's most efficient operationally?

Yes. I mean I think for us, like we did take down stand-alone CapEx by $50 million to kind of this quarter, as you can see in our updated guidance. I think a little bit less activity. I think for us, it's really going to be a judgment call depending on what we view the macro environment looking like over time. Like I definitely agree with you that the market and the downside risk feels a little better today, but I'd say there's still a tremendous amount of uncertainty with regards to commodity prices and what the overall economy does. So I think for us, we're being patient, we're in wait and see mode. Like I said, if you have a little bit of outperformance in Q2, that's going to show itself, I think, very modestly in our production numbers. But going forward, I think it's going to be really a judgment call, and we're going to react to what we feel like is the best real-time information we have and make a call as we get there.

The returns will be driven more by commodity prices than by operational efficiencies. Within a specific region, our team can easily increase or decrease activity without any issues, as they have demonstrated before. There is value in maintaining the same crews and rigs, but we are not reluctant to make changes if it is justified.

And the next question comes from John Freeman from Raymond James.

Really like the steps that were taken with these marketing agreements, the outline on Slide 7. Any help you all can provide on just sort of how to think about the impact of the GP&T sort of unit costs the next couple of years in light of these agreements?

Right now, there won't be a change to GP&T based on those agreements. We have some flexibility to do different things with gas over time that could change that, but we talked about that then. So right now, I don't need to adjust GP&T.

And what we've shown on Slide 7, the $0.10 per Mcf and the $0.50 per barrel, that's net of all expected implied costs.

Okay. That's good to know. And then on the same topic, I mean, you all highlighted that you've sort of the midstream strategy has sort of evolved over time as you all become one of the largest, both oil and gas producers in the Permian. You talked about kind of doubling the size of the midstream and the marketing team. And we've recently seen some of the large E&Ps start moving more towards kind of stepping up or expanding their kind of midstream presence, taking ownership of midstream assets. Just as you all think about just given your size, the evolution of the company, is that a direction that you all may head eventually?

Yes, I think we definitely evaluated options like that as part of the deals we've announced in this Q2 release and some other ones that we've been working on. I think our view on that by and large, has been the same with regards to midstream and kind of large-scale infrastructure projects is that those really don't compete with the returns of our upstream business and that's by a wide margin. I think we're seeing such attractive rates of returns at the wellhead that we think it's more prudent as capital allocators to focus our efforts on doing what we do best, which is drilling, completing wells, and making oil. I think those projects are good. I think, probably better fit for more infrastructure-like capital for us. And we're able to get all of the benefits other than the equity investment kind of from the types of deals that we've done, and I think that's probably the right base case going forward.

And the next question comes from Neil Mehta from Goldman Sachs.

I just would love you to unpack a little bit more about your downturn playbook, which you alluded to in your remarks and in the release. Just for those of us on the line, talk about what your downturn strategy is to make sure that if we are going through a period of softer commodity, how do you ensure that you come out if it's stronger?

Yes. I mean I think the kind of most important part of that is having a high-quality business and a strong balance sheet. I think the quality of our business shows itself on our leading low breakevens in the Permian and a balance sheet that's been in a top position of strength for really as long as we've been running this business. If you're going to go through a downturn, it starts with asset quality and balance sheet. I think we've actually proven over time that we really think the best opportunities for investing in E&P can be periods of kind of market panic and dislocation. Like Will said, that can show itself in a lot of ways. We did a lot of this, albeit on a somewhat smaller scale in Q2, which is buying high-quality assets at lower than mid-cycle prices. It's buying back shares when you believe the pricing is truly dislocated. It's all of that while making sure your balance sheet is strong throughout kind of from peak to trough. For us, that's something we've been talking about for the last couple of years, and we're actually excited about the opportunity to do some of those strategies and execute those pretty well in Q2. Although it's probably a shorter period of dislocation than a lot of the ones we've seen, things could turn to get at some point in the future, and we'll always be ready.

There's been a lot of talk about mergers and acquisitions in some of the larger cap conference calls, and I’d like your perspective. You have effectively consolidated assets with strategic bolt-ons and transformative mergers and acquisitions. Do you see Permian Resources as a consolidator or potentially as a seller in the future? I understand it's a complex question, but I believe it's an important one.

No, that's a fair question and a good one. I think given our leading cost structure, we've always seen Permian Resources as the logical consolidator of Delaware Basin assets today. Frankly, we're really excited about that opportunity set and what's in front of us. We talked about it, but our ground game efforts remain strong. We continue to find larger scale acquisitions like the Barilla Draw acquisition last year, the Apache bolt-on earlier this year, and several hundred million dollar deals in between. We're confident that our pipeline remains robust, and we'll be able to find those types of attractive acquisitions that enhance our business. While we don't have a perfect crystal ball, I would say we're really excited about the opportunities available as a consolidator in the Delaware. On the flip side, we truly believe our business has significant potential on a stand-alone basis. If we keep executing at our current levels, we can continue to grow free cash flow per share as we have since inception. Consequently, we drive substantial outperformance compared to the broader market and peers on a total shareholder return basis, as demonstrated in the past and illustrated on Slide 9. Ultimately, our goal has always been to pursue what we believe creates the most long-term value for shareholders, whether that involves acquiring assets or divesting them, buying businesses, or ultimately selling our business. Every decision we've made running this business has been with shareholders in mind. Together, our team owns over 6% of the outstanding equity of Permian Resources stock, so I believe investors can be assured that we will continue to align with the entire investor base and take actions that will yield the highest long-term returns and create the most value for investors, whichever path that may be. We're fortunate to be in a position of shared purpose with our investors and remain focused on what makes the most sense over the long term.

And the next question comes from Kevin MacCurdy from Pickering Energy Partners.

The market may be a little spoiled as we usually get an update on lower well costs from you guys. I realize maybe there's some moving pieces with the tariffs, but your quarterly CapEx was very good, and you started off the call mentioning record drilling times. Any thoughts on the magnitude of efficiency or drilling improvements you still see down the pipeline?

Look, I think we proved to ourselves this quarter that the best wells can be better than we've seen in the past. I didn't even mention it, but we drilled 5 of our fastest 10 wells ever in Q2. So we're starting to really push the envelope of the best wells. We need to keep making progress on the average well and on the worst wells. On the drilling side, time directly correlates to the bottom line. You save about $100,000 every day you can cut. I think we've proven to ourselves there's a lot of stuff we can go get, and we've done it now on a handful of wells. We just have to go do it on the average. Yes, you're right, like Q2, our well cost on a per foot basis probably remained flat compared to Q1. I think some of that is we drilled a little bit shorter lateral lengths. You don't get quite the efficiencies just based on how the schedule shook out. But if you look at the kind of work we've done on the frac side and the progress we've made on the kind of top quartile of drilling side, I think there's a lot of tailwinds into the back half of the year.

Great. Sounds like there's still some improvement to come. And as a follow-up, any change to how you're seeing the cadence of turnarounds this year? How much of your program do you have left to execute in the back half of the year?

It's the same numbers we've put out there, the $275 million net of the $10 million that we dropped from the original budget. I think we're slightly back half-weighted, but it's the same as we last talked to you all.

And the next question comes from Philip Jungwirth from BMO. Please go ahead.

On Permian gas marketing, there are a number of projects in development to take gas to the Gulf Coast, but we're also seeing proposed projects to move volumes to the Rockies and, even based on yesterday's news, the West Coast. So while it's early on those options, just wondering how much you're considering these other outlets as a way to maximize netbacks and ultimately, how much Waha exposure would you look to maintain given there should be some tightening in the differential after 2026?

Yes. I mean, I think the short answer is we're excited about all these projects. We've been firm believers for a long time that we need more pipes out of the basin sooner. We're pretty excited about just the broader backdrop, and I'd say the willingness of pipeliners to get out ahead of the kind of growth we've seen and expect to continue to see in the Permian. We think this is a great thing for Permian Resources and a great thing for the Permian Basin. I think it will ultimately be a great thing for the owners of these pipelines. We're not just focused on going to the Gulf Coast on the gas side; we're open and excited to explore different markets. We're really just trying to solve for what we think is going to bring the best netback for every molecule of gas that we make. I think we'll be constantly evaluating each and every one of these. I'd say in terms of how much Waha do we want long-term, we've historically said we used to sell about 20% to 25% of our gas outside of the basin. We'd like to reverse that over time. The right long-term answer for PR is probably 20% to 25% of our gas sales at Waha, something like that. We like that flexibility and having the options continue to sell gas in the basin over the long term because there are a lot of interesting things that could happen, potentially some exciting developments.

Okay. And then congrats on the Fitch upgrade. It sounds like the others are going to follow here shortly, but besides the lower cost of capital, sticking with the marketing angle here, just how the IG rating at all 3 agencies benefits you in terms of these opportunities? Could it open up any potential deals that would otherwise not be available?

Yes. I think investment grade, I'd call it modestly helpful relative to these agreements like we've entered into really attractive agreements with the ratings that we have. All these things, whether it's incrementally better terms on the midstream agreements, more flexibility to do longer-term debt, or more availability of credit through the cycle, are all positives for us from a balance sheet perspective. Fitch recognized the fact that our financial metrics and financial strategies are consistent with or superior to a lot of our IG peers, and we're focused on getting the rest of the way there.

And the next question comes from Zach Parham from JPMorgan.

I wanted to follow up on the marketing deals. We've seen a couple of your peers sign some power deals in the basin linked to power pricing. Is that something you've had any negotiations on or that you're considering doing?

Yes. We've looked at all of them. I think that's something we've spent a lot of time on over the past kind of 12 or 18 months. I think we haven't seen any in-basin gas sales deals that we think we can improve our netback relative to the other opportunities. We haven't seen anything interesting on the power side in the areas where we think we need the power the most. Most of what we've seen on the power side has been in Texas, where we have really good grid connectivity. The area where we've needed more power connectivity has continued to be in New Mexico, and we haven't seen a lot of projects there to date, but are certainly open to them in Texas, New Mexico, wherever they come, and we'll continue to evaluate them as they come across our desk.

And then my follow-up is just on your hedge book. You added a little bit during the quarter. Can you just update us on how you're thinking about hedging on a go-forward basis?

Yes. No change on overall hedge strategy, which is roughly 30%, 20%, 10% hedged 1, 2, and 3 years out. We're there on '25, and we're making good progress on '26. What you've seen from us is like we're flexible on how we get there. We're not going to force ourselves into those equations, but we try to be nimble and lean in when we see what seems like pretty clear dislocations like we saw in June.

With our balance sheet where it is today, we're fortunate we can be really patient. I think we're going to try to hedge more if we think prices are higher and we could be comfortable hedging less if there are a few opportunities to lock in what we view as attractive prices. We're building flexibility as the quality of our business grows. I think being opportunistic in late June and locking in prices during that period of positive volatility was a great opportunity for us.

And the next question comes from John Abbott from Wolfe Research. Please go ahead.

I want to go back to Slide 7 and the marketing agreements. I appreciate the free cash flow guidance for 2026, but it looks like the amount of the capacity increases out to 2028. So I guess just to help us sort of triangulate things. As you sort of look out to 2028, you look at strip pricing, how would you describe the potential impact on free cash flow beyond 2026 lease agreements?

Yes, I think there is considerable movement across various markets and strip pricing extending to 2028. We believe that the existing contracts will yield greater benefits than those projected for 2026. We are actively seeking new opportunities for optimization. According to the charts on Slide 7, we have about two-thirds of our gas volume contracted and about half of our crude volume contracted. This reflects a combination of our current contracts and anticipated future optimizations. You can expect that contracted volume to increase after 2026.

Appreciate it. And then just following up, you did close on the Delaware acquisition during the quarter. I mean, the assets are in-house. Could you maybe speak to a little bit more about the opportunities in terms of savings and optimization now that you have the assets in hand?

Yes. So we closed 6 weeks ago and took over operations shortly thereafter. From an integration perspective, I'd say it was kind of integrated within a week. There are some quick wins on the production side, just kind of obvious shared people; we don't need as many people because we already have pumpers in the exact area. Ultimately, there'll be some wins on the water disposal side or water recycling side, just given the connectivity of the assets. What's unique to this deal, in particular, is what our land team will do with the assets. If you think about when we rolled that deal out, it was unique in that it came with a lot of really good operated units and a lot of non-op under PR, but also had some good quality, more scattered acreage that our team will go to work on right away. We are in the middle of discussing multiple trades right now that will get us into either core up in areas where we'd like to core up or get us into new units that we otherwise wouldn't be in. Not a lot of specifics, and I don't have a look back on the numbers since we're 4 weeks in from operating or something like that, but we've had some quick wins on the people and water disposal side, and I'm expecting some big wins to come on the land side.

And the next question comes from John Annis from Texas Capital.

For my first one, I assume the margin for error is extremely narrow to drill top decile wells, let alone 5 of 10 fastest in 1 quarter. Can you remind us of what has to go right to be able to do this? What did you do to have to go right 5 times in 1 quarter? And then just how far the average is to these high watermarks?

To drill a top decile well, it's crucial to avoid any unplanned trips. We must minimize non-productive time, ideally close to zero, and primarily engage in rotating while drilling. Achieving success in these areas is rare and not typical. The best wells we've drilled this quarter took about 5.5 and 6 days, while our average is around 10.5 to 11 days, which is significantly higher. This is very encouraging for us. Our drilling team has multiple wells demonstrating that this is achievable, and now they need to work on making this performance standard. If successful, reducing drilling time to 5 or 6 days could lead to substantial cost savings, potentially nearing 10% of our overall well costs. While I don’t expect this to happen in the second half of this year, it is certainly an important long-term objective for us.

Terrific. For my follow-up, in the release, you highlight chemical and power optimization projects as drivers of maintaining low LOE during the quarter. Can you provide some more color around those drivers and specifically what you are doing on the power side?

Our production team is consistently dedicated to increasing run time while reducing costs, which can be a challenging balance since longer run times often require more investment. We have implemented two microgrid projects, which involve larger-scale power generation connected to various locations. This setup allows field personnel to spend less time traveling by consolidating service locations, resulting in economies of scale and improved run time. Both of our microgrid initiatives have been very successful, with power costs declining by 30% for each. We are currently assessing our potential opportunities; concentrating wells in one area makes investment in power lines more efficient. Conversely, widely spaced wells can diminish overall return on investment. We continuously explore innovative solutions to enhance our operations, and the production team takes great pride in their work, as evidenced by the successful projects launched this quarter.

And the next question comes from Leo Mariani from ROTH Capital.

I just wanted to clarify some of your commentary on well costs. If I heard you guys right, second quarter was kind of flattish dollar per foot. It sounds like shorter laterals sort of drove that. But if I heard you right, it sounds like the expectation is that those well costs will come down in the second half of the year. Is that correct? Additionally, can you talk about how much of that you think can be driven by kind of sticky efficiencies? Is there a cost component as well that you may benefit from?

Yes. The three things that we have in the back half of the year are my expectations that you're going to see an efficiency step up. We demonstrated the ability to do it, and I have no reason to believe we can't replicate what we did in Q2 in the back half of the year. With the volatility we've seen in kind of depressed oil prices, service costs are coming down a little bit. There wasn't a ton of room to give, but where we've had it, we've gotten some, and we've made some vendor changes and are always trying to figure out the best way to optimize the balance of efficiencies and cost per unit on our side. There is a little offset in casing costs. Casing costs are up just due to tariffs, and I'd say you gave a little bit back there. Net-net, I'd expect cost per foot to be down in the back half of the year.

Okay. Appreciate that. And I guess just from a high-level perspective, obviously, you talked about the macro. If I read your tone right, it sounds like maybe there's a little bit of caution, given the current landscape. Should people generally expect you guys to try to hold oil flattish for the foreseeable future in this kind of uncertain macro landscape and just remain laser-focused on reducing costs?

Yes. I think that's probably a good generalization. We've come out of several years of very pronounced growth and have said time and again this year that it does not feel like it's the right kind of market to return to what's been if you combine organic and inorganic several years of double-digit production growth. With the amount of uncertainty in the supply side and the demand side we've seen today, we don't think that makes sense. I think forecast for the near term, that could be months or quarters until we have more confidence in returning to growth. Kind of flattish to low single-digit growth is the right expectation, and that's what this year has looked like.

And the next question comes from Noah Hungness from Bank of America.

Will, James, and team. To start off, I was hoping if you guys could expand on the comments around the federal lands and the commingling that's been opened up. What does that mean for Permian Resources? Does that allow you to access what was potentially stranded acreage or extended DSUs?

No. It doesn't do that. It really just allows us to build central tank batteries in New Mexico like we use currently in Texas. If you have 2 units that back up to each other and one had state and one had federal acreage. Prior to that, we would have to build completely separate batteries, which for us would waste capital, and generally just not be the most efficient way to run our business. With the new ability to commingle in New Mexico, we can build one battery and just meter the wells like we do in Texas. A little bit of capital savings really, I just say the world is better, smaller footprint, less places to drive to, and a little capital savings. We're excited about it. It's a common-sense thing that needed to happen for a long time, and we're happy to have finally got it done.

That makes sense. On the updated guidance, capital increased by the $20 million that I think you guys had previously flagged. But the TIL count working interest and lateral footage was unchanged. So is the increase in the CapEx from moving capital into a higher cost part of the Delaware? Or is there other spending involved there?

No. The $20 million increase was just due to 8 wells that were work-in-progress wells that we took over from Apache where a little bit of capital flowed through to us between effective date and closing or just post-closing.

And the next question comes from Paul Diamond from Citi. Is the increase in the CapEx from moving capital into a higher cost part of the Delaware, or is there other spending involved? William M. Hickey, Co-CEO, responded that the $20 million increase was due to 8 wells that were work-in-progress wells taken over from Apache, where a little bit of capital flowed through to them between the effective date and closing or just post-closing.

Just wanted to quickly touch on the balance sheet. You're also sitting at about $450 million in cash on our numbers that accretes pretty solidly over the course of the second half of the year. Can you remind us what you think is the right number to carry there? Or is there a plus or minus? Or what's the right number you want to hold on the balance sheet?

Yes, this is Guy. I think the right number is $500 million to $1 billion. We've seen and demonstrated the benefit of having this liquidity. We talked about last quarter we went into Q2 with the best balance sheet we've ever had. We executed on the downturn playbook as we described, and we sit here with $0.5 billion of cash on the balance sheet and 1x leverage. Our approach to the balance sheet and ensuring we have firepower for when we go into these downturns is a huge part of how we think we can deliver shareholder return over time.

Got it. Makes sense. And then just one quick follow-up on ground game cadence. You guys have done a pretty good job over the first half of the year. Should we expect those numbers to remain stable, like 1,000-plus acres per quarter? Or is there any reason to think the opportunity set is growing or shrinking?

Yes, it's definitely a bit inconsistent. We feel great about our ground game pipeline. The recent acquisition in Apache, New Mexico, really opens up new opportunities for us. I anticipate that we'll see more ground gains moving forward. The second quarter is likely to be a bit softer due to recent volatility. The fluctuations in oil prices at the start of the quarter take some time for both sellers and buyers to adjust their expectations. Overall, I expect we'll achieve more ground game activity in the latter half of the year.

And we have no further questions that came through at this time. I will now hand the call back to Will Hickey for closing remarks. Please go ahead, sir.

Thanks, John. This was an outstanding quarter for the PR team. Not only do we continue our operational track record in the field but also quickly executed on our downturn playbook, which we believe will drive real value for shareholders. Given our high-quality asset base and fortress balance sheet, we believe we can continue this execution and value creation going forward in any commodity price environment. Thanks to everyone for joining the call today and following the Permian Resources story.

Thank you. This concludes our conference call for today. Thank you all for participating. You may now disconnect.